Bitumen recovered from oil sands as one of the petroleum resources has been regarded only as a preliminary or alternative resource for the next generation until now. Even though the bitumen itself is inferior in quality, products obtained from the bitumen have strong competitiveness to those obtained from crude oil. Further, a possibility of bitumen as an alternative to crude oil is also rising from a viewpoint of cost. Besides, Canadian oil sands have a good reputation for their overwhelming reserve that is almost equal to that of Saudi Arabia's crude oil. For example, the hydrocarbon reserve in Alberta State and its neighbor area in Canada is one of the largest reserves in the world. Above all, different from geopolitically unstable areas such as the Middle East and African countries, Canada has extremely low investment risks. To ensure a stable energy supply is an extremely important task for resource-poor Japan and any other country. From this point of view, therefore, Canada has been ranked as a current supply area of valuable petroleum resources.
In the production of bitumen from the oil sands, recently, the bitumen located at depths in which development by surface mining is difficult to conduct, has gotten much attention. As a method capable of realizing the recovery of bitumen from oil sands located at these depths, the in-situ recovery method attracts attention, such as the SAGD (steam assisted gravity drainage) process and the CSS (cyclic steam stimulation) process. Thus, a technical development of the in-situ recovery method has been energetically advanced (see “Development of Canada oilsands—Future challenges”, Kiyoshi Ogino, Journal of the Japanese Association for Petroleum Technology, Vol. 69, No. 6 (November 2004) pp. 612-620).
According to the in-situ recovery method, a high-temperature steam is injected into high viscosity oil in an oil sand layer, in which the oil is not able to flow at a normal temperature. The viscosity of the oil is reduced by the heat. Resultantly, aggregated high-temperature condensate and oil are recovered by the steam injection. Therefore, “water” for producing a large amount of high-temperature steam is required. In order to produce steam, for example, the SAGD process described below uses water of about three times as much as the amount of oil to be produced. Meanwhile, in Canada, the quantity of water intake that is allowed for use is limited by the severe environmental policies (regulation) in the states, and effluent-injecting layers having a sufficient capacity are not located in the neighbor area. Therefore, water recycling shall be applied (see “Water recycling for oil sands development”, Nobutoshi Shimizu and Tsuneta Nakamura, Journal of the Japanese Association for Petroleum Technology, Vol. 70, No. 6 (November 2005) pp. 522-525).
In order to recycle the water to be used in the production of bitumen, the following methods have been used heretofore. Firstly, Flow (1) of a conventional method is explained (see FIG. 8). The bitumen-mixed fluid 20A recovered from the oil sand wells (oil sand layers 1) in the in-situ recovery method, is treated with a separator 2 including a knock-out drum and a treater, to extract bitumen 3. Then, an oil-containing water (which may be in some cases referred to “produced water”) 20B separated from the bitumen is cooled to a predetermined temperature with a cooler (heat exchanger) 4, and then the oil is separated and removed from the water with the flow of a skim tank 5, an induced gas flotation 6, an oil removal filter 7 using walnut shell, and a deoiled tank 8. Thus, a conventional treated water 20D′ is recovered. The oil-water separation according to this method is fundamentally gravity separation in which use is made of the difference in specific gravity between oil and water. In FIG. 8, the label “T” described in the box indicates a temperature of the fluid in the portion. The label “Oil” indicates the content of oil. (These have the same meanings in FIGS. 1 and 9.)
At the subsequent stage, a hardness component is removed from the treated water 20 D′ with a flow of a lime softener 9, an after filter 13, and a weak acid cation softener 11. The resultantly-treated water is supplied to a once-through-type boiler (not shown) as a boiler feed water 20C. Recently, the following water treatment is also applied: pure water is produced by means of an evaporator 12 as a desalination process in place of a softening treatment in the above-described conventional flow (1), and the thus-produced water is fed to a drum-type boiler (not shown) as a boiler feed water 20C (see Flow (2) of another conventional method in FIG. 9).
In the conventional flow (1), however, a number of equipment and steps are required for oil-water separation, which result in a troublesome operation and a high cost of equipment with a difficult operation and maintenance. Further, there is reported a case example in which organic scales deposit in a heat exchanger and a boiler, thereby causing corrosion cracking due to thermal stress (see “Water recycling for oil sands development”, Nobutoshi Shimizu and Tsuneta Nakamura, Journal of the Japanese Association for Petroleum Technology, Vol. 70, No. 6 (November 2005) pp. 522-525). It is assumed to be a primary cause that though oil droplets of a relatively large particle size can be separated, oil droplets of a small particle size or emulsified oil cannot be separated by gravity separation (see “TORR™— The Next Generation of Hydrocarbon Extraction From Water”, M. J. Plebon, Journal of Canadian Petroleum Technology, Vol. 43, No. 9 (September 2004) pp. 1-4). On the other hand, in the conventional flow (2), when an evaporator is applied to the softening/desalination step of the subsequent stage, scale troubles caused by organic matters in a boiler arise. Therefore, scale troubles are still remaining obstacles to the advancement of these conventional methods (see “Water recycling for oil sands development”, Nobutoshi Shimizu and Tsuneta Nakamura, Journal of the Japanese Association for Petroleum Technology, Vol. 70, No. 6 (November 2005) pp. 522-525).